The stable complex emulsions generated during shale oil extraction pose significant challenges for oil-water separation, yet the underlying stabilization mechanisms-particularly those involving interactions between crude oil components and residual fracturing additives-remain poorly understood. Here, we systematically investigate the emulsion stabilization mechanisms and demulsification strategies for a typical shale oil produced fluid from the Shengli Oilfield. Through active components of crude oil combined with interfacial tension and dilatational rheology measurements, we demonstrate that asphaltenes are the primary determinants of emulsion stability. More importantly, we reveal a synergistic interaction between asphaltenes and the residual fracturing thickener at the oil-water interface. This synergy generates a composite interfacial film exhibiting both high elasticity (dilatational modulus up to 31.0 mN/m) and low interfacial tension (1.4 mN/m), which accounts for the exceptional stability of the field emulsion. Stratification experiments show that gravitational settling concentrates asphaltenes in the lower layer by nearly 290-fold (from 0.01 % to 2.9 %), producing a "high asphaltene, high water, high viscosity" system with dramatically enhanced stability. Based on this mechanistic understanding, we develop a blended demulsification strategy combining a tailored polyether demulsifier (Th-2) with a water clarifier (QS). This formulation achieves 97 % water separation and 99 % oil separation within 8 h at 70 degrees C, effectively overcoming the "oil separation without water separation" limitation of single demulsifiers. This work reveals a previously unrecognized asphaltene-thickener synergy that produces a high-elasticity, low-tension composite film, and demonstrates that a simple blended demulsifier (Th-2 + QS) outperforms novel synthetic alternatives in cost and scalability.

Solid-liquid flows in horizontal pipelines occur in petroleum and mining applications, where patterns easily form at low concentrations and velocities. This study combines experiments with Eulerian-Lagrangian simulations to analyze the transition from a continuous bed to distinct patterns, not systematically studied before. First, we examine mean statistical quantities-sediment thickness, velocity, pressure drop, and concentration profiles-neglecting micro-structures. These quantities from experiments and simulations are captured by either two-layer or three-layer model. Pattern formation depends on particle size and bulk velocity. Larger particles or lower velocities promote a continuous bed with ripples or intermittent slugs of nonuniform length; smaller particles or higher velocities favor disconnected, crescent-shaped dunes. Pattern-induced velocity fluctuations are analyzed using kinematic wave theory and spectra; wave speed increases with bulk velocity. Voronoi¨ tessellation serves to quantify spanwise particle elongation dynamics within the patterns. Particle clustering is also investigated: in slugs, particles can remain bound through up to two consecutive slugs; in dunes, they disperse immediately upon leaving their original dune. Decorrelation time and particle-particle vs. particle-fluid interactions are also examined. Within the sediment regime, interparticle contacts dominate particle motion. Decorrelation time and contact-to-hydrodynamic stress ratio decrease with increasing bulk velocity but exhibit deviations at critical transitions-such as onset of slugs or dunes or changes in dune count-highlighting sensitivity of particle dynamics to pattern evolution.

The adhesion of hydrates to marine sediments plays a critical role in affecting extraction efficiency and wellbore safety during gas hydrate production. This study investigates the micro-mechanical properties of hydrates on different mineral surfaces by using a high-pressure micro-mechanical force device (HP-MMF) to quantify hydrate-mineral adhesion forces, and systematically examines the effect of contact duration. Adhesion tests were performed using laboratory-synthesized methane hydrate particles and three representative minerals of marine sediments (silica, mica, and illite) under both brine-saturated and pure-water-saturated conditions. The analysis reveals how adhesion force varies with mineral type and contact duration. The results provide experimental evidence and quantitative insight into the interaction mechanisms between methane hydrates and sediment minerals, offering a valuable reference for predicting and controlling sediment migration behavior and flow conditions during hydrate extraction.

Repurposing existing refined oil pipelines for green methanol batch transportation is a cost-effective pathway for large-scale low-carbon fuel delivery, yet severe mixing between methanol and gasoline impairs transport economy and safety. Conventional mixing control schemes rely on isolating agents or fixed-flow adjustment with limited active regulation capacity, so this work aims to develop a material-free pulsed pumping technology to suppress interfacial mixed oil. A validated SPS transient flow–mixing coupled model is built based on a real South China long-distance pipeline, and minute-scale trapezoidal-wave pumping is proposed inspired by cardiac pulsation; three key parameters, including rest period duration, acceleration–deceleration ratio and flow amplitude ratio, are systematically scanned via numerical simulation. The results reveal a non-monotonic correlation between rest period and mixed oil volume, with the optimal 40 min interval cutting mixed oil by 18.37%. Waveforms with acceleration time no shorter than deceleration time achieve stable 18–20% mixing reduction, and the optimal max–min flow ratio of 10:7 delivers a 19.38% reduction. The integrated optimal parameter set reduces mixed oil by 19.4–19.8%. This study provides operable field parameters and a low-cost active mixing suppression strategy for methanol–gasoline sequential pipelines, offering theoretical support for the reuse of existing oil pipelines for green fuel transportation.

The controlled dissociation of natural gas hydrates (NGHs) poses a significant challenge in gas production from hydrate-bearing sediments and in mitigating hydrate blockages in petroleum pipelines. In this study, molecular dynamics (MD) simulations and experimental measurements of hydrate particle interactions are combined to elucidate the effect of cocamidopropyl dimethylamine (CDA) on the dissociation kinetics of methane hydrate and on the interparticle behavior during carbon dioxide hydrate dissociation. The dissociation rate in the CDA system exhibits a nonlinear relationship with concentration. Upon heating, the dissociation rate increases exponentially with temperature, following Arrhenius' law. During depressurization, inhibitor solubility decreases at low pressures, leading to reduced dissociation efficiency. For convenience, CO2 hydrate was used in the experiments. Microscopic observations confirmed the concentration effect of CDA, but at high concentrations, formation of an interfacial film inhibited dissociation. This study provides microscopic insight into the concentration-dependent role of CDA in hydrate dissociation under heating and depressurization.

The temperature and pressure ranges of the marine environment are conducive to the formation of CO2 hydrates. Subsea CO2 sequestration technology based on the hydrate method, owing to its excellent CO2 storage capacity and long-term stability, is a promising strategy for reducing greenhouse gases. To date, few studies have reported on the formation kinetics of CO2 hydrates in multi-factor coexisting systems under the conditions of nondiagenetic hydrate reservoirs in the South China Sea, warranting investigation. In this study, two L16 (4<^>4) orthogonal experiments were designed, and a high-pressure reactor (autoclave) was used to conduct a systematic experimental investigation of CO2 hydrate formation in systems where salt, quartz sand, and L-methionine coexist. The results show that sand content is the dominant factor affecting CO2 hydrate formation; a low sand content of 40 wt% is most favorable to the formation kinetics. In monosized sand layers, pore size exerts clear and distinguishable effects on nucleation, mass transfer, and final filling, with 40-70 mesh fine sand performing best. Meanwhile, introducing grain-size gradation enhanced mass-transfer efficiency, reduced reliance on high concentrations of L-methionine, and increased formation rates under high-salinity conditions. This work also elucidates the growth morphology and formation mechanism of CO2 hydrates in saline sand and amino acid systems. These findings provide a fundamental understanding of the formation kinetics of CO2 hydrates in multivariable coexisting systems and offer reference value for optimizing sequestration using amino acids and for selecting storage sites for CO2 hydrates in South China Sea sediments.

The development and selection of cost-effective, efficient, and environmentally friendly hydrate antiagglomerants (AAs) are of great significance for addressing the challenge of hydrate-induced blockages in complex multiphase flow systems and advancing hydrate slurry transportation technologies. In this study, the antiagglomeration performance of amide-based surfactants (DPLA and DPCA) in gas-dominated systems (CO2) was first investigated using a micromechanical force (MMF) apparatus. The results demonstrate that, compared with the system without inhibitors, the addition of amide-based AAs at varying concentrations led to a maximum reduction of 50.00% in the critical hydrate formation time (82.44 -> 41.22 min; 1 wt % DPLA). The cohesive force between CO2 hydrate particles decreased by 33.83% to 52.09%, with the largest reduction of 52.09% (26.87 mN/m -> 12.88 mN/m; 1 wt % DPLA). The cohesive force between CO2 hydrate particles and wall droplets dropped by 20.14% to 50.30%, with a maximum reduction of 50.30% (656.61 mN/m -> 326.31 mN/m; 0.5 wt % DPCA). Then, a visualized rheometer was utilized to investigate the viscosity behaviors of slurries during THF hydrate formation in water-dominated systems in the presence of amide-based AAs for the first time. The results indicate that compared with the blank system, the addition of amide-based AAs at varying concentrations led to a maximum reduction of 93.9% in the stable viscosity of slurries (1220.57 mPa & centerdot;s -> 74.52 mPa & centerdot;s; 0.2 wt % DPCA). Amide-based AAs could effectively reduce the cohesive forces between hydrates and particles/wall droplets, preventing the emergence of large hydrate aggregates, thereby enhancing the flowability of the hydrate slurry. This suggests that amide-based surfactants have immense potential in improving the stability and transportability of hydrate slurry systems.

During deep-sea oil and gas production, hydrate blockage threatens the safe operation of subsea production systems, and efficiently removing the blockage is an important research objective. The effects of DPLA concentration, temperature, pressure, and the number of wax molecules on hydrate dissociation were analyzed through RDF, MSD, RDR, potential-energy variations, and configurations. For oil-water systems, increasing temperature (283 K-313 K) or lowing pressure (0.1, 1 and 10 MPa) lead to higher hydrate dissociation rate. Liquid hydrocarbons adsorb methane molecules, suppressing nanobubble formation, and maintaining dissociation driving force. The activation energy for hydrate dissociation in the oil-water system is higher than that in water-dominated the system. Adding DPLA to the oil-water system accelerated hydrate dissociation. With increasing DPLA concentration, the dissociation rate first increased and then decreased, indicating an optimal concentration for promoting hydrate dissociation (0.51 wt % in this work). This behavior results from the combined effects of DPLA-induced nanobubble formation, migration toward the oil-water interface, and hin-drance of guest-molecule mass transfer. In addition, a higher number of wax molecules in the oil-water system increased the mass-transfer resistance of guest molecules during hydrate dissociation and lowered the dissoci-ation rate. The controlling mechanism gradually shifted from reaction-rate control to mass-transfer limitation. This study reveals the coupling mechanism of anti-agglomerant-wax on hydrate dissociation at the molecular scale. These findings are significant for preventing hydrate plugging and for guiding the application of anti-agglomerants.

The influence of salt on gas hydrates formation in pores is important for the efficient exploitation of gas hydrates in actual sediments. In this study, the experiments of methane hydrate formation in pores with different concentrations (0.00 wt%, 0.40 wt%, 1.00 wt%, 2.00 wt%, and 3.50 wt%) of sodium chloride (NaCl) brine were carried out in a glass micromodel. The effects of salinity on the micro growth morphology and growth rate of methane hydrate formed by free gas and dissolved gas in pores were studied. The results showed that, for the hydrate formed by free gas in pores, the hydrate was preferentially formed at the gas-liquid interface and then grew toward the gas body center. The hydrate growth rate along the gas-liquid interface (vinterface) was 100 to 150 times higher than that toward the gas bubble center (vcenter). Meanwhile, with the increase of salt concentration, the vinterface decreased. However, for the vcenter, it increased first and then decreased with the increase of the salt concentration, and the maximum average vcenter was obtained in the pores containing 0.40 wt% NaCl brine. The possible promotion mechanism of NaCl on the vcenter was analyzed in detail. For the hydrate formed by dissolved gas, the hydrate growth rate decreased with the increase of the distance between the hydrate growth front and the surrounding free gas bubble, and it also decreased with the increase of the salt concentration in pore water. This work is helpful in understanding the influences of salt on the microscopic growth characteristics of hydrate formed by free gas and dissolved gas in pores, so as to provide guidance for the efficient exploitation of gas hydrates.

During the transportation of oil and gas pipelines, the adhesion and aggregation of hydrate particles on the pipe wall are prone to cause pipeline blockage, which seriously impairs the safe and efficient transportation of energy. Taking cyclopentane hydrates as the research object, this study investigated the effects of contact time, wall wettability, and the concentration of kinetic hydrate inhibitor poly(N-vinylcaprolactam) (PVCap) on the adhesion force between hydrates and the wall of X80 pipeline steel by combining a high-precision micromechanical force measurement system with microscopic morphology observation and analysis. The results show that the adhesion force increases with prolonged contact time: it is dominated by capillary liquid bridge force in the initial contact stage with slow growth, and after exceeding the critical time, the sintering effect becomes the dominant factor, leading to a rapid rise in adhesion force that eventually tends to stabilize. Wall wettability significantly influences the adhesion force, and enhanced wettability improves the adhesion force by increasing the liquid bridge volume and the hydrate-wall contact area. PVCap concentration exerts a non-monotonic effect on adhesion force-first decreasing and then increasing. At low concentrations (0.25-1 wt%), PVCap molecules adsorb on the hydrate surface to form a physical barrier, reducing adhesion force. At high concentrations (1.5-2 wt%), excessive PVCap damages hydrate shell integrity, releasing free water to expand the liquid bridge volume and increase adhesion force. This study provides a theoretical basis for eliminating or reducing hydrate blockage in deep-sea oil and gas pipelines.

Wax deposition is a major challenge in oil and gas production, particularly in offshore fields like the Bohai Sea. This study investigates the deposition mechanisms of two oils (B oil with high wax content and J oil with high resin and asphaltene content) under varying temperatures, production rates, and time using cold deposition experiments. For B oil, deposition thickness increases by 126% (from 5.72 to 12.94 mm at 20 m & sup3;/d) as oil-wall temperature reduces from 42-40 degrees C to 27-25 degrees C, following classical wax aging rules. High-temperature gas chromatography (HTGC) shows that heavy components (C40-C60) dominate deposits, with 42% higher content than crude oil. In contrast, J oil exhibits atypical behavior with initial deposition thickness reaching 8.2 mm due to rapid gelation. Despite wall temperatures exceeding the wax appearance temperature (WAT), deposits form via colloidal aggregation, with minimal thickness increase (<5% over 8 hr). HTGC analysis shows weaker aging effects (C40-C60 content only 8% higher than crude oil), highlighting the dominance of viscosity-driven gelation over wax crystallization. This work enhances the understanding of wax deposition mechanisms in wellbore production and suggests that effective wax removal for waxy crude oils with high resin and asphaltene content requires combining pour-point depressants and viscosity-reducing agents.

System reliability assessment of buried pipelines subjected to landslide hazards is computationally challenging due to high-dimensional spatial variability and complex nonlinear large-deformation responses. This paper proposes AK-SYS-SIS, integrating Sequential Importance Sampling (SIS) into the Active Learning Kriging framework for system reliability analysis. The method constructs an approximate optimal sampling density to adaptively guide candidates toward critical boundaries of multiple failure modes, while a composite learning strategy selectively updates only the most critical surrogate component. Two stochastic large-deformation finite element frameworks, RCEL-OLHS and GCRCEL-OLHS, are developed within the Coupled Eulerian-Lagrangian (CEL) technique to simulate earthquake-induced and rainfall-induced landslide–pipeline interactions, respectively. These frameworks incorporate Karhunen–Loève random field discretization, strain-softening constitutive models via Abaqus VUSDFLD/UMAT subroutines, modified Mohr-Coulomb plasticity, and soil rotating anisotropy, with GPU-accelerated random field generation for the rainfall scenario. Benchmark validations on series, parallel, and hybrid systems demonstrate that AK-SYS-SIS improves efficiency by 4–6 orders of magnitude over Monte Carlo Simulation with relative errors below 3%. In engineering applications, the method identifies system failure probabilities with fewer than 100 finite element evaluations, reducing computational cost by 94%–96.5% compared to direct simulation.

In addressing the issue of hydrate blockage in subsea pipelines, and promoting the development of green oilfields, it is crucial to find efficient, economical, and environmentally friendly kinetic hydrate inhibitors (KHIs) and their synergists. In this study, molecular dynamics simulations were employed to systematically investigate the effects of the traditional inhibitor poly (N-vinyl caprolactam, PVCap), at similar concentrations, combined with an amino acid (glycine, Gly), its short peptides (tripeptide 3G and pentapeptide 5G), and a composite mixture (3G + Gly) on the growth behavior of methane hydrates. The results indicate that there are significant differences in the inhibitory efficacy of the various composite systems, with the following order: PVCap + 5G > PVCap-2; PVCap + 5G > PVCap + 3G + Gly; PVCap + Gly > PVCap + 3G > PVCap + 3G + Gly. Analyses of molecular conformation, hydrate cage count, density distribution, and methane nanobubble evolution reveal that 5G enhances the arrangement and adsorption of PVCap on the hydrate surface, strengthening its ability to form hydrogen bonds with water molecules, and further promotes the formation of methane nanobubble. Gly exhibits moderate synergy by forming hydrogen bonds with the hydrate interface without competing with PVCap. In contrast, 3G competes for the binding sites of PVCap on the hydrate surface, weakening PVCap's ability to form hydrogen bonds with water molecules. When combined with Gly, 3G and Gly create an "intermolecular mismatch" effect, further reducing the inhibitory performance of the combined inhibitor and the formation of bubble. This study presents molecular insights on the synergistic mechanism of commercial KHIs with amino acids and its short peptides of varying polymerization degrees at the molecular level, offering theoretical guidance for designing resource-efficient and sustainable kinetic hydrate inhibitors.

Deep-sea oil and gas exploration is conducted under complex environmental conditions, including high pressure and low temperature. The formation, agglomeration, and deposition of natural gas hydrates can induce pipeline blockage, thereby markedly reducing oil and gas transportation efficiency and causing substantial economic losses. To address hydrate-blockage risk assessment, this study develops an XGBoost-based hydrate risk assessment model. By examining the causal relationships between key parameters and pipeline blockage, hydrate-blockage risk is categorized into two levels: high risk and low risk. Quantitative results indicate that the blockage risk generally increases when the hydrate volume fraction approaches or exceeds approximately 10%, or when the apparent viscosity approaches or exceeds approximately 16 mPa & sdot;s. SHAP-based interpretability analysis further confirms the agreement between model outcomes and experimental observations, and the proposed model achieves an accuracy of 96.3%. The results of this study can assist engineering personnel in realtime identification of potential hydrate-blockage risk and in implementing preventive measures in advance.

The stability of CO2 hydrate in clay-rich porous media is fundamental to the safety of geological CO2 storage. While the TBAB is known as hydrate promoter, its stabilizing effect under the combined influence of thermodynamic condition and dynamic flow remains poorly understood. This study systematically investigates the stabilizing effect of TBAB on CO2 hydrate stability in the kaolinite pores by molecular dynamics simulation across a range of temperature (255-295 K) and pressure gradients (0-50 MPa/nm). It is found that TBAB mitigates hydrate decomposition by forming a continuous, protective TBA+-CO2-H2O ternary composite structure near the hydrate. Innovatively, it is found that the stabilizing mechanism is non-monotonic with respect to flow. The moderate shear flow could enhance stability by organizing TBA+ ions into a more effective barrier, whereas high flow rates disrupt this layer. Similarly, high temperature facilitates the escapement of CO2 from the ternary composite structure accelerating hydrate decomposition. These molecular-level insights offer crucial guidance for practical applications, informing the selection of favorable temperature conditions and suggesting that moderate injection flow rates may contribute to enhanced storage security. Ultimately, this work provides crucial insights for developing additives to ensure the long-term safety and efficiency of hydrate-based CO2 storage.

The study of nearshore seabed topography is crucial for scientific research, environmental management, and resource development. Despite the advancements in satellite remote sensing technology, accurately reconstructing nearshore seabed topography remains challenging due to the limitations of traditional empirical models, which struggle to achieve high inversion accuracy across varying environmental conditions. To address this gap, this research introduces a high-precision nearshore seabed topography reconstruction model based on convolutional neural networks, termed CNN-NSTR, which enhances inversion accuracy by integrating multisource multispectral image data. We have compared the performance of traditional empirical models with various CNN-NSTR structures. The findings reveal that the CNN_ln4-NSTR model surpasses all others across accuracy metrics, achieving a mean square error of 1.35 m and a mean absolute error of 0.881 m for bathymetry in the 0-30 m depth range-improvements of 51.26 % and 38.82 %, respectively, over the Stumpf empirical model. This significant enhancement in accuracy demonstrates the potential of CNN-NSTR to overcome the shortcomings of empirical methods, particularly in complex nearshore environments. Furthermore, this research contributes to the broader field of oceanographic research by providing a more precise and scalable approach to coastal monitoring, marine resource management, and environmental conservation.

Gas hydrate is viewed as a potential energy, and the multihorizontal depressurization wells are expected to achieve its commercial production. However, how to optimize the multihorizontal wells layout in hydrate reservoirs is controversial. In this research, the numerical study on the hydrate exploitation from the Shenhu Area of the South China Sea by the dual-horizontal depressurization wells (DHDW) was conducted, and the optimal spatial position of DHDW was first studied. It is realized that the optimal spatial position of DHDW for gas hydrate production should be in the center of the hydrate layer. Based on this conclusion, the influences of the well spacing between DHDW (ranging from 22 to 582 m) on hydrate exploitation were then investigated. It is found that there was a strong interference between DHDW when the well spacing was smaller, leading to the lower total produced gas volume. When the well spacing increased to a certain value, the interference disappeared, and the total produced gas volume reached the maximum. On this basis, a new method to calculate the optimal well spacing (d o) between DHDW was proposed. According to the calculation, when the exploitation period was 10 years, the d o between the DHDW values was 73.06 m. Finally, the influences of the permeability (k) in the hydrate layer (2.9-145 mD) and the exploitation period (t) of gas hydrate (5-30 years) on the d o were further studied. The function relations of d o and k, and d o and t were obtained, respectively. Furthermore, the implications for the optimal layout of multihorizontal depressurization wells in hydrate reservoirs were discussed. This study could provide guidance for the efficient exploitation of gas hydrate.

The composite phase change materials (CPCMs) are always created by integrating high thermal conductivity additives with paraffin, facilitating heat dissipation during the battery discharging process. However, under cold conditions, the battery needs to utilize the paraffin intrinsic low thermal conductivity to reduce heat loss. Thus, creating a CPCM that rapidly dissipates heat at high temperatures and retains heat at low temperatures is a new challenge. This research develops a novel CPCM with the water droplets-SiC particles network inside the paraffin matrix. 5 wt% SiC particles and 15/25/35 wt% water enhance the thermal conductivity from 0.24 Wm- 1K- 1 to 1.29/1.45/1.68 Wm- 1K- 1, respectively. The network acts as a thermally conductive pathway, leading to an average decrease of 3.7 degrees C or 4.4 degrees C in the final battery temperature at 2C or 3C discharge rate. Water crystallizes and releases heat, thereby this process maintains the temperature of battery at 0 degrees C for an extended period exceeding 16 min. Moreover, network stability is related with water content. After 15 heating or cooling cycle tests, droplet coalescence or deformation is less prone to occur when CPCMs with a water content of 15/25 wt% than that with 35 wt%, preventing the network structural breakage.

This study investigates the impact of hydroxyl functionalization on biosurfactants for methane hydrate formation, emphasizing their potential in sustainable gas storage. Sodium oleate (SO) and hydroxylated sodium oleate (HSO), derived from oleic and ricinoleic acids, respectively, were synthesized and evaluated as eco-friendly promoters. HSO outperformed SO and conventional surfactants, such as sodium dodecyl sulfate (SDS), particularly at low concentrations (50 ppm). Methane hydrate formation with HSO achieved an impressive conversion efficiency of 94.95 % at 50 ppm, surpassing SDS. HSO significantly enhanced storage capacity up to 161.86 v/v, exceeding the 157.90 v/v capacity of SDS. The optimized balance of hydrophilic and hydrophobic properties in HSO enhanced gas-water interactions, enabling rapid hydrate crystallization and stabilization. Furthermore, HSO exhibited superior performance in saline environments, achieving higher methane consumption and water-to-hydrate conversion rates compared to SO and SDS. This highlights the advantages of using seawater as a medium for methane hydrate formation, as it reduces operational costs and enhances sustainability. Methane hydrate pellet formation experiments revealed that HSO led to a faster formation rate and higher conversion degree. The resulting pellets were more stable and exhibited greater methane storage capacity. In long-term stability tests, HSO-based pellets retained more methane than SO-based pellets after 15 days at -5 °C. Additionally, HSO demonstrated excellent thermal stability in both pure and saline water, remaining structurally intact at elevated temperatures. These findings highlight the potential of molecularly tailored biosurfactants, such as HSO, as green and efficient alternatives to conventional surfactants for methane storage and transportation. This advancement aligns with global sustainability goals and supports the broader adoption of hydrate-based solidified methane technology.

Drag reducers have become a common method for reducing resistance and increasing transportation efficiency in pipeline transportation of waxy crude oil. The prominent heat transfer weakening effect of drag reducers may impact the deposition of waxy oil. This study uses cold finger experiments to clarify wax deposition characteristics and mechanisms in drag‐reduced waxy oil. The wax deposition mass and components are examined under different temperatures, stirring rates, drag reducer dosages, and types. The results show that a low dosage of drag reducer at high stirring rates can simultaneously reduce the total wax deposition and the overall wax content in high waxy oil. 5 mg/kg drag reducer can reduce total wax deposition by up to 15.66% and overall wax content by 7.26%. A systematic investigation reveals that adding drag reducers changes the carbon number distribution in the wax deposition layer. This change is similar to the effect of increasing wall temperature. The heat insulation and transfer weakening effects of drag‐reducing fluids are likely the main mechanisms inhibiting the increase in wax deposition mass and wax content. The heat insulation effect reduces the temperature gradient near the pipe wall, while the transfer weakening effect decreases radial heat transfer. However, under low stirring rates and high dosages, the deposition mass of the drag‐reduced waxy oil system increases, with the adhesive effect of polymer‐type drag reducers becoming more pronounced. These findings provide a foundation for optimizing drag reducer usage in waxy crude oil pipelines, potentially leading to significant energy savings and improved operational efficiency.